The present invention relates generally to the field of enhanced hydrocarbon recovery and more particularly to a method for characterizing multilayer subterranean reservoirs.
Initial hydrocarbon production from subterranean reservoirs is generally referred to as "primary" production. During primary production, only a fraction of the hydrocarbon in the reservoir is recovered. Thereafter, additional hydrocarbon can be recovered employing enhanced hydrocarbon recovery techniques by injecting fluids such as water, steam, nitrogen, CO.sub.2 or natural gas into the reservoir and such subsequent production is generally referred to as "secondary" or "tertiary" production. Enhanced recovery techniques generally depend on the injected fluid to displace the hydrocarbon from its in-situ location and direct it towards a producing well from which it can be recovered. Because of the substantial economic cost required to develop and implement enhanced recovery techniques, it is critically important for a reservoir engineer to characterize the storage and flow capacity of a hydrocarbon bearing reservoir. More particularly, it is important for the reservoir engineer to describe the distribution of porosity, permeability, and thickness of the various reservoir layers and to be able to optimize both the spacing and operating conditions of injection and preduction wells for producing hydrocarbons from a multilayer reservoir. Geological, geophysical and petrophysical analyses can provide a good starting point for an initial estimate of such reservoir properties. However, such analyses can be seriously limited especially with regard to their inability to accurately describe the vertical variation of in-situ reservoir permeability.
Experience in the petroleum industry has indicated that reservoir storage and flow parameters obtained from geological, geophysical and petrophysical data can be used to develop a model of the reservoir and thereafter the model can be input into a numerical reservoir simulator to obtain predictions of reservoir response or performance during enhanced hydrocarbon recovery. The goal of such numerical reservoir simulators is to predict reservoir performance in more detail and with more accuracy than is possible with simple extrapolation techniques. Unfortunately, one seldom knows enough about a reservoir to develop an accurate model describing reservoir storage and flow parameters without testing it in some way and iteratively altering the model of the reservoir until it produces acceptable results. Given the limited amount of information available to delineate the reservoir model, the most useful--and usually the only--way to test the model description of reservoir storage and flow parameters is to simulate past performance of the reservoir and compare the simulation with actual, historical performance. Typically, such "history matching" is done on a trial-and-error basis by modifying selected reservoir storage and flow parameters upon which the reservoir model was derived and iteratively running the numerical reservoir simulator until eventually the simulated performance matches the historical performance.
The history matching technique can be an especially useful and powerful technique to determine reservoir storage and flow parameters. Although such numerical reservoir simulators coupled with trial-and-error history matching techniques have been used with some success to develop reservoir storage and flow parameters, they can consume substantial amounts of computing time as well as be quite expensive and frustrating because reservoir storage and flow parameters can be very complex with numerous interactions. While there are many methods of combined numerical reservoir simulation and trial-and-error history matching, no universally applicable method has evolved. Moreover, such techniques typically involve iteratively, manually adjusting selected reservoir storage and flow parameters and recalculating reservoir performance with the numerical reservoir simulator. Making changes by guessing or by following one's intuition can be expensive and will usually prolong the history matching analysis.
In order to address the aforementioned shortcomings of conventional history matching techniques, the present invention provides an automated method of history matching whereby flow parameters of the reservoir can be determined more quickly and less expensively than can be achieved using present techniques. Additionally, the present invention provides a novel method for determining the optimum injection and production well pattern on spacing as well as optimum operating conditions for producing hydrocarbons from a multilayer reservoir.